Coalbed methane (CBM) has become a significant component of U.S. natural gas supplies. CBM production increased to 2.9 Bscf/day of gas supply in 1997, accounting for about 6% of total U.S. natural gas production (Stevens et al., “Enhanced Coalbed Methane Recovery using CO2 Injection: Worldwide Resource and CO2 Sequestration Potential” SPE 48881; 1998).
Most CBM reservoirs are produced under primary recovery methods, i.e., without secondary recovery methods involving injection of recovery-enhancing fluids. The proportion of original gas-in-place that can be recovered is dependent on reservoir properties, in particular, the absolute permeability of the coal bed. In high permeability reservoirs (>20 millidarcy (md)), recovery can theoretically be up to 80% of original gas-in-place. CBM recovery in moderate permeability reservoirs (5 to 20 md) can range from 50 to 70%, while recovery in low permeability reservoirs (≦5 md) can range from 10 to 50%. CBM recovery is also dependent on production economics. Presently, low permeability reservoirs are unlikely to produce CBM at commercial rates without some form of enhanced recovery. Moreover, the volume of CBM remaining after primary production, especially in moderate and low permeability reservoirs, is significant. For example, it is estimated that primary production in developed areas of the San Juan Basin alone, which are generally high permeability reservoirs, may leave behind as much as 10 Tscf of natural gas in areas with depleted coal beds (Stevens et al., ibid).
New technologies have been proposed for enhanced coalbed methane recovery (ECBM) to recover a larger fraction of CBM in place. The two principal variants of ECBM are (1) inert gas stripping by injecting nitrogen (N2), which is a weaker adsorbing gas (WAG) than methane (CH4), and (2) displacement desorption by injecting carbon dioxide (CO2), a stronger adsorbing gas (SAG) than CH4.
Generally, as an injected WAG enters a coal bed through a wellbore, the partial pressure observed for CBM in the vicinity of the wellbore is substantially reduced. Most significantly, it is believed that the CBM partial pressure in the wellbore vicinity can be reduced to particularly low levels as a WAG is injected. Consequently, it is believed that as the CBM partial pressure is reduced, the CBM desorption rate from coal increases dramatically and the CBM is swept substantially through the coal bed in a mixture with the WAG to a production well. The production rate of the WAG and CBM is controlled by the total pressure in the formation, which is maintained as high as possible by injection during this process. Some WAG is sorbed into the coal, but there is a net reduction in the total gas (i.e., CBM and WAG) content of the coal.
By contrast, generally, as a gas that is more strongly adsorbing than CH4 is injected into the coal bed, it is believed to be preferentially adsorbed into the coal. Since the SAGs are generally not produced, this process works well for both ECBM recovery and sequestration of SAGs, such as CO2 or hydrogen sulfide (H2S). And there is a net increase in the total gas (i.e., SAG and CBM) content of the coal. Also, the SAG is typically trapped in-situ and is not produced unless the injected SAG front reaches the production well (i.e., breakthrough). At breakthrough, this type of SAG injection and CBM displacement process would be terminated.
Thus, a secondary benefit associated with a SAG injection/CBM displacement process, such as a CO2-ECBM process, is that it can sequester large volumes of CO2. There is an increasing concern that some gaseous effluent streams from industrial processes may cause environmental problems, and, as a result, these streams should not be released into the atmosphere. CO2 is a constituent of many gaseous effluent streams released from industrial processes and whose release into the atmosphere is causing increasing concern. Should global restrictions on CO2 emissions be promulgated, CO2-ECBM could be one of the few profitable technologies for sequestering CO2. For instance, tradable credits for CO2 sequestration could dramatically improve CO2-ECBM economics over current performance levels.
Some global warming proponents relate excess nitrous oxide (N2O), as well as CO2, emissions to climatological change. Also, nitrogen oxide (NOx) emissions, such as nitric oxide (NO) or nitrogen dioxide (NO2), in sufficient concentration, can be toxic to health and the environment. Additionally, sulfur oxide (SOx) emissions, in sufficient concentration, can contribute to the production of “acid rain,” which can have a detrimental effect on various plant and aquatic life.
Thus, it is possible that many or all of these gases could become more stringently regulated, at least in certain market-developed countries or regions, such as the United States, Canada, Japan and Europe. Consequently, this prospect of increasing regulatory stringency for some or all gaseous emissions can hamper many industries because the combustion of virtually any hydrocarbon fuel with air produces an effluent containing CO2, N2, and gaseous combustion products.
For instance, various countries, including, among others, France, Germany, the United Kingdom, Canada and Japan have agreed to seek internal approval and adoption, within their respective jurisdictions, of the Kyoto Protocol. The Kyoto Protocol ensued from the United Nations Framework Convention on Climate Change, held in December 1997 at Kyoto, Japan. Under the Kyoto Protocol, each participant agreed in principle to “implement and/or further elaborate policies and measures in accordance with its national circumstances” to, among other things, enhance energy efficiency and protect reservoirs of certain atmospheric gases not controlled by the Montreal Protocol (e.g., CO2). Generally, the Kyoto Protocol addressed emissions of greenhouse gases, including CO2, CH4, N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6). While the United States and Australia have elected not to follow the Kyoto Protocol, they tend to address greenhouse gas emissions with national programs.
In addition to being a hydrocarbon combustion product, CO2can be produced by natural processes and released to the environment during a non-combustion process. For example, CO2 is produced by thermal and biogenic processes, which are believed to form hydrocarbons such as oil, natural gas, or coal. CO2 often is recovered with these hydrocarbons and released to the atmosphere by various post-production steps.
The increasing concern over the atmospheric release of CO2 and other undesired gas-emission compounds demands a method(s) for disposing of the compounds, once collected.
As discussed above, various ECBM recovery and sequestration processes have been disclosed. For example, U.S. Pat. No. 6,412,559 (Gunter, Mavor and Law, Jul. 2, 2002) describes a process for recovering CH4 from a coal bed and/or sequestering a SAG in a coal bed by cyclic SAG injection with intervening shut-in periods.
In order to make injection and/or production processes more efficient, it is desirable to determine the coal bed's porosity, absolute permeability and effective permeability to gas and water for a given injection pressure, production pressure, injected gas composition and/or produced gas composition. These data would then be used to design, monitor, and improve the efficiency of ECBM and/or sequestration processes. These data can also be used to design, monitor and improve the efficiency of primary production processes.
Coal is characterized by two distinct porosity systems, discussed more fully below: a primary porosity system and a secondary porosity system (“SPS”). The primary porosity system contains the vast majority of the gas-in-place and the sequestration capacity, while the SPS provides the conduit for mass transfer between wells and the primary porosity system.
Primary porosity system gas storage is dominated by adsorption phenomena because of the high surface area to volume ratio caused by very small pore spaces within the organic material and the close proximity of gas molecules to molecules within solid materials. The gas and solid molecules attract each other due to weak intermolecular forces known as Van der Waals forces. Due to attraction to the solid, gas molecules are packed closer together than expected from the pressure and temperature conditions. The equivalent density of the molecules in the sorbed state is similar to the density of the molecules in a liquid state. In coal beds, the primary porosity system is relatively impermeable due to the small pore sizes. Mass transfer for each gas molecular species is dominated by diffusion that is driven by the concentration gradient (i.e., change in concentration along a flow path divided by the length of the flow path) for each molecular species.
Commercially productive CBM reservoirs contain a well-developed SPS. Without natural fractures, commercial production from CBM reservoirs would not be possible due to the low permeability of the primary porosity system. Flow through the SPS is due to pressure gradients through the fracture system towards production wells.
Gray (“Reservoir Engineering in Coal Seams: Part 1—The Physical Process of Gas Storage and Movement in Coal Seams” SPE 12514, 1987) recognized that coal permeability changes during production due to (1) phase relative permeability effects (i.e., degree of saturation affects gas and water relative permeabilities) and (2) changes in effective stress within the coal seam. Generally, Gray observed that permeability is a function of effective stress within the coal seam. So, when the coal matrix shrinks with gas desorption, a concomitant decrease in effective stress leads to increased permeability. On the other hand, when coal bed cleats close with reduced fluid pressure, a concomitant increase in effective stress leads to decreased permeability. More specifically then, Gray teaches that permeability decreases when fluid pressure is reduced (i.e., coal bed cleats close). On the other hand, he observes an opposing effect where permeability is increased when coal shrinkage occurs with gas desorption.
Later, Stevenson et al. (“Adsorption/Desorption of Multicomponent Gas Mixtures at In-Seam Conditions” SPE 23026, 1991) produced adsorption isotherms for binary and ternary mixtures of CO2, CH4 and/or N2. The adsorption isotherms showed that equilibrium gas (free gas) and adsorbate phase (sorbed gas) compositions differ considerably. Accordingly, Stevenson et al. teach that the total amount of gas adsorbed strongly depends on a gas mixture's composition and the system pressure.
And Arri et al. (“Modeling Coalbed Methane Production with Binary Gas Sorption” SPE 24363, 1992) described multi-component gas sorption using extended Langmuir isotherms as the basis for equilibrium between free and sorbed gas.
In the mid-1990's, those skilled in the art recognized that a significant feature of coal is its ability to sorb substances, including gases and stimulation chemicals. Upon sorption, the coal matrix swells and closes natural fractures, thereby reducing natural fracture permeability. Likewise, when a gas that is more weakly adsorbing than the in-situ gas is injected into the formation, the coal matrix will shrink, as weaker adsorbing fluid displaces the stronger adsorbing fluid from the coal matrix. Consequently, matrix shrinkage and swelling affect the coal bed's SPS porosity, absolute permeability and effective permeability to gas and water.
However, coal beds are most frequently heterogeneous and may exhibit significant anisotropy in both the vertical and horizontal directions. Also, coal is often found in layers separated by shale or sandstone. Therefore, core samples frequently fail to provide reliable estimates of a coal bed's in-situ SPS porosity or permeability. Likewise, pressure fall-off tests on their own typically yield insufficient information to sufficiently characterize a coal bed.
Accordingly, those skilled in the art have endeavored to produce a model for calculating SPS porosity and/or permeability. As an example, Levine developed a rock mechanics model to evaluate the effect of matrix shrinkage on fracture aperture width and absolute permeability as fluid pressure declines during primary CBM production (“Model Study of the Influence of Matrix Shrinkage on Absolute Permeability of Coal bed Reservoirs,” Gayer, R. and Harris, I. eds., Coalbed Methane and Coal Geology Geological Society Special Publication No. 109, The Geological Society, London, pg. 197-212; 1996).
Levine recognized that absolute permeability could increase during primary production due to coal matrix shrinkage resulting from CBM desorption. But, citing Gray (ibid), Levine also recognized that, without matrix shrinkage, fractures could be sealed due to increasing pore volume compressibility with decreasing fluid pressure. Levine's model covered the relationship between gas desorption strain and fluid pressure decrease during CBM production. More specifically, Levine's CBM production model assumed a curvi-linear relationship between sorption strain and pressure during production. The model also used the Langmuir isotherm model for determining CH4 and CO2 data. Fracture width changes during primary production were modeled by Levine using five relationships:                                           ⅆ            ɛ                                ⅆ            p                          =                              (                                          ɛ                max                            ·                              P                50                                      )                                              (                                                P                  50                                +                P                            )                        2                                                  k        =                                            (                              1.013                ×                                  10                  9                                            )                        ·                          b              3                                            12            ·            s                                                            ɛ          p                =                                            1              E                        ·                          (                              1                -                                  2                  ⁢                  v                                            )                        ·            Δ                    ⁢                                           ⁢                      P            f                               εs=Ms·ΔPfb2=b1+εp·s+εs·s                where        εmax theoretical maximum strain at infinite pressure        P50 pressure at 50% of maximum strain        P pressure        k permeability        b fracture width        s fracture spacing        εp fracture closure strain due to pressure change        E Young's modulus        ν Poisson's ratio        Pf pressure of fluids residing within coal        εs matrix shrinkage coefficient        Ms matrix shrinkage coefficient        b2 new fracture width        b1 previous fracture width        
Levine selected “base case” and ranges of values for b1, E, ν, s, εmax and P50 and conducted parameter sensitivity analyses to show the effect of each variable. In each case, one of the six variables was changed while the remaining variables were held constant at the “base case” value. Although Levine acknowledges that there are interrelationships between the variables, there is no suggestion on how to account for the interrelationships. For example, Levine's sensitivity analysis showed that “permeability should increase more for coals with a higher Young's modulus; however, coals with a higher Young's modulus will tend to have a correspondingly lower matrix shrinkage coefficient as well and would probably actually exhibit a smaller increase in permeability.” (Levine, p. 211)
Although Levine recognized parameter sensitivity in predicting permeability, including the sorption effect of CO2 over CBM, he did not provide guidance on how to use each equation to predict a specific absolute permeability value for a specific reservoir condition. Levine's analysis also did not account for effects by or on injection processes. Accordingly, Levine's model was limited to primary production cases.
Recognizing some of the limitations of Levine's model, Palmer and Mansoori (“How Permeability Depends on Stress and Pore Pressure in Coalbeds: A New Model” SPE 36737; 1996 and SPE 52607; 1998) developed a theoretical model for calculating pore volume compressibility and permeability, during primary production, as a function of effective stress and matrix shrinkage. The theoretical model was intended to be more rigorous than the Levine model. The Palmer & Mansoori Model (“P&M Model”) is presented below:                               ϕ                      ϕ            0                          =                  1          +                                                    c                m                                            ϕ                0                                      ⁢                          (                              P                -                                  P                  0                                            )                                +                                                    c                0                                            ϕ                0                                      ⁢                                          (                                                      K                    M                                    -                  1                                )                            ·                              (                                                      bP                                          1                      +                      bP                                                        -                                                            bP                      0                                                              1                      +                                              bP                        0                                                                                            )                                                                        (                              P            &                    ⁢                                           ⁢          M          ⁢                                           ⁢          Model                )                            where        φ porosity        φ0 porosity at original reservoir pressure        P reservoir pressure        P0 original reservoir pressure        cm matrix compressibility, psi−1         c0, b parameters of Langmuir curve match to volumetric strain change due to matrix shrinkage        K bulk modulus        M constrained axial modulus        
But again the P&M Model was limited to predicting strain effects during primary production, without accounting for strain effects arising with gas injection or changes in gas composition. Palmer & Mansoori also identified the following relationship between permeability and porosity:       k          k      0        =            (              ϕ                  ϕ          0                    )        3                  where        k permeability        k0 virgin permeability        
For convenience, hereinafter, we will refer to the portion of any model that accounts for porosity changes arising from pressure changes as pressure strain. Meanwhile, we will refer to the portion of the model that accounts for porosity changes arising from gas content changes as sorption strain.
Mavor et al. (“Increasing Coal Absolute Permeability in the San Juan Basin Fruitland Formation” SPE 39105; 1998) used the P&M Model to match the pressure and production behavior of three wells completed in Fruitland Formation coal seams in the San Juan Basin of Colorado. Primary CBM production resulted in coal seam permeability increases of 2.1 to 7.1 times the original permeability. Well tests were conducted in three wells early in the life of the well and later after significant depletion had occurred. The P&M Model was calibrated with the data from one well. The calibrated model was then used to compute the expected permeability ratio as a function of the pressure ratio. The computed relationship matched the results for the other two wells without additional changes. This analysis confirmed that the P&M Model was applicable to a primary CBM production and that the cubed power of the porosity ratio used to quantify the relationship between coal bed permeability and SPS porosity was correct.
The P&M Model accounts for changes in SPS porosity when pressure is reduced and when the coal matrix shrinks as the volume of gas sorbed into the coal matrix declines during production.
However, while the P&M Model accounts for coal matrix shrinkage, it is only applicable for a constant (i.e., static) gas composition. Moreover, the P&M Model is used to predict how permeability changes as pressure is decreased in drawdown, but not during injection. According to Palmer & Mansoori, “During drawdown of a reservoir by primary production, effective stress increases and permeability decreases due to cleat compression. However in coalbeds, drawdown leads to desorption of methane, and this is accompanied by matrix shrinkage which opens the cleats and leads to permeability increase. The two effects of cleat compression and matrix shrinkage act in opposite directions on permeability.”
Accordingly, the P&M Model accounts only for changes in permeability and porosity during production, in particular during primary production. Because primary production does not involve injecting other gases, as in the case of ECBM recovery techniques, the produced gas composition is relatively constant until late in the life of a reservoir. And because the P&M Model assumes a constant gas composition, it is applicable only to production of original in-situ gas composition.
However, in ECBM recovery and/or fluid sequestration projects, the produced and/or injected gas compositions are dramatically different from the original in-situ composition. Such changes also affect the strain parameters dramatically. Accordingly, the P&M Model is not useful for predicting permeability or porosity changes in ECBM or fluid sequestration projects where gas other than original in-situ CBM is produced and/or injected into the coal bed. Also, the P&M Model uses initial coal bed reservoir properties as a reference point for determining the extent of change in reservoir permeability. However, after a fluid is injected or produced, the reservoir properties at the initial reservoir pressure have changed even if the reservoir pressure is substantially the same. Accordingly, the P&M Model becomes less effective, if not inapplicable, for predicting changes in permeability or porosity due to fluid injection or production with changing gas composition. These same disadvantages also apply to the less rigorous Levine model.
As an alternative approach to determining reservoir permeability, among other reservoir properties, such as CBM recovery rate and % CBM that can be economically recovered, Puri in U.S. Pat. No. 5,501,273 (Mar. 26, 1996) and a 1995 conference paper by Puri et al. (“A Micro-Pilot Approach to Coalbed Methane Reservoir Assessment,” Intergas '95 Proceedings, University of Alabama/Tuscaloosa, pp. 265-274, May 15-19, 1995) describes a method using field data obtained from an injection flow-back test, which data, in turn, is used in a numerical reservoir simulator, along with injection data and any prior primary production data, to model the coal bed reservoir. More specifically, Puri's method is particularly suited for predicting CBM recovery rate and % CBM recovered in an ECBM recovery process. Meanwhile, the injection/flow-back test involves injecting a gaseous desorbing fluid containing at least 50% (vol.) N2 into a formation. Injection rate data is collected during the injection step. The wellbore is then shut-in and the pressure response is measured. In a subsequent flow-back step, at least a portion of the injected fluid is produced, while production rate data and produced fluid composition data are obtained. Then, the collected field data is used in conjunction with reservoir modeling techniques, preferably by history matching with a numerical reservoir simulator for modeling the formation so ECBM recovery characteristics can be determined.
Puri teaches that the injection rate increase obtained for a given increase in injection pressure is dependent on the stress dependent permeability relationship exhibited by the formation. As defined by Puri, the stress-dependent permeability relationship describes the change in the effective permeability that occurs in the formation as the pore pressure changes. Puri further teaches that as injection pressure increases, pore pressure increases, which, in turn, causes the effective permeability of the formation to increase. Accordingly, Puri considers only changes in permeability arising from fluid pressure changes, such as a drop in fluid pressure that leads to cleat closure, and hence, reduced permeability for the SPS. But Puri fails to account for coal matrix shrinkage or swelling arising from the effects of different gases on the coal matrix.
For instance, the relationship between the effective permeability ratio, Kf/Ki,, and pore pressure is illustrated in Puri's FIG. 1, (U.S. Pat. No. 5,501,273) which compares a theoretical relationship based on laboratory data (curve 25), history matching coal seam behavior before and during air injection (curve 27) and history matching coal seam behavior during flow-back after air injection (curve 29).
In fact, in 1991, Puri et al. published the theoretical relationship between Kf and Ki, which was later re-introduced in FIG. 1 of U.S. Pat. No. 5,501,273 as curve 25 (see “Measurement of Stress Dependent Permeability in Coals and its Influence on Coalbed Methane Production” Paper 9142 Proceedings of the 1991 Coalbed Methane Symposium, University of Alabama/Tuscaloosa; May 13-16, 1991). The theoretical relationship is based on absolute permeability measurements performed on a coal sample maintained under uniaxial strain conditions to simulate an overburden with constant axial stress. The testing avoided relative permeability effects, as the coal sample was saturated with brine and then depleted of brine while maintaining a constant axial confining stress.
But, since the coal sample contained no gas, the theoretical relationship cannot account for changes in permeability arising from gas content changes. In fact, when comparing the history-matched and theoretical Kf/Ki relationships in FIG. 1 of his patent, Puri stated that “The discrepancy between theoretical curve 25 and fitted curve 27 during the pre-injection production and air injection period is believed to be a result of the simulator not accounting for the relative permeability relationship exhibited over time by the formation.” (col. 21:4-8). Therefore, Puri fails to recognize the importance of, and thereby account for, a sorption strain component to better predict the coal bed's permeability in view of different types of injection gas compositions.
Moreover, Puri suggests that his method for determining ECBM recovery characteristics using a test gas containing at least 50% (vol.) N2 could equally be applied to ECBM recovery techniques using an injected gaseous desorbing fluid containing either at least 50% (vol.) N2 or at least 50% (vol.) CO2. And yet Puri does not account for matrix shrinkage or swelling due to gas composition. However, as discussed more fully below, N2 and CO2 have quite different effects on a coal bed's permeability and porosity.
Accordingly, there is a need for a method for predicting a coal bed's SPS porosity and/or permeability for different injected and/or produced fluid compositions at different injection and/or production pressures. Moreover, there is a need for a model that can be applied to injection and/or production processes. More particularly, there is a need for a method for predicting a coal bed's SPS porosity and/or permeability for better assessing the economics and efficiency of both CBM production and/or sequestration projects.